Embodiments described herein generally relate to downhole pumping systems and methods. More particularly, embodiments described herein relate to systems and methods for deliquifying subterranean gas wells to enhance production.
Geological structures that yield gas typically produce water and other liquids that accumulate at the bottom of the wellbore. The liquids typically comprise hydrocarbon condensate (e.g., relatively light gravity oil) and interstitial water in the reservoir. The liquids accumulate in the wellbore in two forms, both as single phase liquid entering from the reservoir and as condensing liquids, falling back in the wellbore. The condensing liquids actually enter the wellbore as a vapor and as they travel up the wellbore, they drop below their respective dew points and condense. In either case, the higher density liquid-phase, being essentially discontinuous, must be transported to the surface by the gas.
In some hydrocarbon producing wells that produce both gas and liquid, the formation gas pressure and volumetric flow rate are sufficient to lift the produced liquids to the surface. In such wells, accumulation of liquids in the wellbore generally does not hinder gas production. However, in the event the gas phase does not provide sufficient transport energy to lift the liquids out of the well (i.e. the formation gas pressure and volumetric flow rate are not sufficient to lift the produced liquids to the surface), the liquid will accumulate in the well bore.
In many cases, the hydrocarbon well may initially produce gas with sufficient pressure and volumetric flow to lift produced liquids to the surface, however, over time, the produced gas pressure and volumetric flow rate decrease until they are no longer capable of lifting the produced liquids to the surface. Specifically, as the life of a natural gas well matures, reservoir pressures that drive gas production to surface decline, resulting in lower production. At some point, the gas velocities drop below the “Critical Velocity” (CV), which is the minimum velocity required to carry a droplet of water to the surface. As time progresses these droplets accumulate in the bottom of the wellbore. The accumulation of liquids in the well impose an additional back-pressure on the formation and may begin to cover the gas producing portion of the formation and detrimentally affect the production capacity of the well. Once the liquid will no longer flow with the produced gas to the surface, the well will eventually become “loaded” as the liquid hydrostatic head begins to overcome the lifting action of the gas flow, at which point the well is “killed” or “shuts itself in.” Thus, the accumulation of liquids such as water in a natural gas well tends to reduce the quantity of natural gas that can be produced from the well. Consequently, it may become necessary to use artificial lift techniques to remove the accumulated liquid from the wellbore to restore the flow of gas from the formation. The process for removing such accumulated liquids from a wellbore is commonly referred to as “deliquification.”
For oil wells that primarily produce single phase liquids (oil and water) with a minimal amount of entrained gas, there are numerous artificial lift techniques. The most commonly employed type of artificial lift requires pulling 30 foot tubing joints from the well, attaching a fluid pump to the lowermost joint, and running the pump downhole on the string of tubing joints. The fluid pump may be driven by jointed rods attached to a beam pump, a downhole electric motor supplied with electrical power from the surface via wires banded to the outside of the tubing string, or a surface hydraulic pump displacing a power fluid to the downhole fluid pump via multiple hydraulic lines. Although there are several types of artificial lift used in lifting oil, they usually require an expensive method of deployment consisting of workover rigs, coiled tubing units, cable spoolers, and multiple personnel on-site.
Initially, artificial lift techniques employed with oil producing wells were used to deliquify gas producing wells (i.e., remove liquids from gas producing wells). However, the adaptation of existing oilfield artificial lift technologies for gas producing wells generated a whole new set of challenges. The first challenge was commercial. When employing artificial lift techniques in an oil well, revenue is immediately generated—valuable oil is lifted to the surface. In contrast, when deliquifying a gas well, additional expense is generated mostly from non-revenue generating liquids—typically, water and small amounts of condensed light hydrocarbons are lifted to the surface. The benefit, however, is the ability to maintain and potentially increase the production of gas for extended time, thereby creating additional recoverable reserves. Typically, at 100 psi downhole pressure, the critical velocity, and hence need for artificial lift, occurs at less than 300 mcfd. One challenge is that large remaining reserve potentials with lower per well revenue streams are needed to justify the price of installing traditional artificial lift technologies.
The second major shortcoming of the existing artificial lift technologies is the lack of design for dealing with three phase flow, with the largest percentage being the gas phase. For example, many conventional artificial lift pumps gas lock or cavitate when pumping fluids comprising more than about 30% gas by volume. However, in many gas wells, the pump may experience churn fluid flow where the pump intake may experience transitions between 100% gas and 100% liquid over a few seconds. In general, the goal of a downhole fluid pump is to physically lower the fluid level or hydrostatic in the wellbore as close to the pump intake as possible. Unfortunately, most conventional artificial lift technologies cannot achieve this goal and thus are not fit for purpose.
With well economics driving limited choices for deliquification, one lower cost option that has been investigated is called “plunger lift.” In a plunger lift system, a solid round metal plug is placed inside the tubing at the bottom of the well, and liquids are allowed to accumulate on top of the plug. Then a controller shuts in the well via a shutoff valve and allows pressure to build, and then releases the plunger to come to surface, pushing the fluids above it. When the shutoff valve is closed, the pressure at the bottom of the well usually builds up slowly over time as fluids and gas pass from the formation into the well. When the shutoff valve is opened, the pressure at the well head is lower than the bottomhole pressure, so that the pressure differential causes the plunger to travel to the surface. Plunger lift is basically a cyclic “bucketing” of fluids to surface. Since the driver is the wellbore pressure it is directly proportional to the amount of liquid it can lift. Also, the older the well, the longer shut-in times are required to build pressure. Besides the safety risks of launching a metal plug to surface at velocities around 1,000 feet per minute, the plunger requires high manual intervention and only removes a small fraction of the liquid column to surface.